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MarketScreener Homepage  >  Equities  >  Nyse  >  EOG Resources Inc.    EOG

EOG RESOURCES INC.

(EOG)
  Report  
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EOG RESOURCES : MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS EOG RESOURCES, INC. (form 10-Q)

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08/01/2019 | 05:04pm EDT

Overview

EOG Resources, Inc., together with its subsidiaries (collectively, EOG), is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad and China. EOG operates under a consistent business and operational strategy that focuses predominantly on maximizing the rate of return on investment of capital by controlling operating and capital costs and maximizing reserve recoveries. Each prospective drilling location is evaluated by its estimated rate of return. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis, allowing EOG to deliver long-term production growth while maintaining a strong balance sheet. EOG implements its strategy primarily by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves. Maintaining the lowest possible operating cost structure that is consistent with efficient, safe and environmentally responsible operations is also an important goal in the implementation of EOG's strategy.

United States. EOG's efforts to identify plays with large reserve potential have proven to be successful. EOG continues to drill numerous wells in large acreage plays, which in the aggregate have contributed substantially to, and are expected to continue to contribute substantially to, EOG's crude oil and liquids-rich natural gas production. EOG has placed an emphasis on applying its horizontal drilling and completion expertise to unconventional crude oil and liquids-rich reservoirs.

Crude oil, natural gas liquids (NGLs) and natural gas prices have been volatile, and this volatility is expected to continue. As a result of the many uncertainties associated with the world political environment, worldwide supplies of, and demand for, crude oil and condensate, NGLs and natural gas and the availability of other energy supplies, EOG is unable to predict what changes may occur in crude oil and condensate, NGLs, and natural gas prices in the future. The market prices of crude oil and condensate, NGLs and natural gas in 2019 will continue to impact the amount of cash generated from EOG's operating activities, which will in turn impact EOG's financial position and results of operations. For the first six months of 2019, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $57.38 per barrel and $2.87 per million British thermal units (MMBtu), respectively, representing a decrease of 12% and an increase of 1%, respectively, from the average NYMEX prices for the same period in 2018. Market prices for NGLs are influenced by crude oil prices and the composition of NGL production, including ethane, propane and butane, among others. Based on its 2019 drilling and completion plans, EOG expects its 2019 total production and total crude oil production to increase as compared to 2018.

During the first half of 2019, EOG continued to focus on increasing drilling, completion and operating efficiencies gained in prior years. In addition, EOG continued to evaluate certain potential crude oil and liquids-rich natural gas exploration and development prospects and to look for opportunities to add drilling inventory through leasehold acquisitions, farm-ins, exchanges or tactical acquisitions. On a volumetric basis, as calculated using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGL production accounted for approximately 77% and 76% of EOG's United States production during the first half of 2019 and 2018, respectively. During the first half of 2019, EOG's drilling and completion activities occurred primarily in the Eagle Ford play, Delaware Basin play and Rocky Mountain area. EOG's major producing areas in the United States are in New Mexico, North Dakota, Texas and Wyoming.

Trinidad. In Trinidad, EOG continues to deliver natural gas under existing supply contracts. Several fields in the South East Coast Consortium (SECC) Block, Modified U(a) Block, Block 4(a), Modified U(b) Block, the Banyan Field and the Sercan Area have been developed and are producing natural gas which is sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary, and crude oil and condensate which is sold to Heritage Petroleum Company Limited. During the second half of 2019, EOG plans to drill three net wells.

Other International. In the Sichuan Basin, Sichuan Province, China, EOG drilled two wells in the first half of 2019 to complete the drilling program started in 2018. EOG completed one drilled uncompleted well from the 2018 drilling program in 2019. All natural gas produced from the Baijaochang Field is sold under a long-term contract to PetroChina.

EOG continues to evaluate other select crude oil and natural gas opportunities outside the United States, primarily by pursuing exploitation opportunities in countries where indigenous crude oil and natural gas reserves have been identified.



                                      -21-

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Capital Structure. One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. EOG's debt-to-total capitalization ratio was 20% at June 30, 2019 and 24% at December 31, 2018. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

On June 3, 2019, EOG repaid upon maturity the $900 million aggregate principal amount of its 5.625% Senior Notes due 2019.

On June 27, 2019, EOG entered into a new $2.0 billion senior unsecured Revolving Credit Agreement (New Facility) with domestic and foreign lenders. The New Facility replaces EOG's $2.0 billion senior unsecured Revolving Credit Agreement, dated as of July 21, 2015, which had a scheduled maturity date of July 21, 2020. The New Facility has a scheduled maturity date of June 27, 2024, and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods subject to certain terms and conditions. The New Facility (i) commits the Banks to provide advances up to an aggregate principal amount of $2.0 billion at any one time outstanding, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $3.0 billion, subject to certain terms and conditions, and (ii) includes a swingline subfacility and a letter of credit subfacility.

Effective January 1, 2019, EOG adopted the provisions of Accounting Standards Update (ASU) 2016-02, "Leases (Topic 842)" (ASU 2016-02). ASU 2016-02 and other related ASUs resulted in the recognition of right-of-use assets and related lease liabilities representing the obligation to make lease payments for certain lease transactions and the disclosure of additional leasing information. The adoption of ASU 2016-02 and other related ASUs resulted in a significant increase to assets and liabilities related to operating leases on the Condensed Consolidated Balance Sheet at June 30, 2019. Financial results prior to January 1, 2019, are unchanged. See Note 1 "Summary of Significant Accounting Policies" and Note 14 "Leases" to EOG's Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Total anticipated 2019 capital expenditures are estimated to range from approximately $6.1 billion to $6.5 billion, excluding acquisitions and non-cash transactions. The majority of 2019 expenditures will be focused on United States crude oil drilling activities. EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program and other uncommitted credit facilities, bank borrowings, borrowings under its $2.0 billion senior unsecured revolving credit facility, joint development agreements and similar agreements and equity and debt offerings.

Management continues to believe EOG has one of the strongest prospect inventories in EOG's history. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer incremental exploration and/or production opportunities.




                                      -22-

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Results of Operations

The following review of operations for the three months and six months ended June 30, 2019 and 2018 should be read in conjunction with the Condensed Consolidated Financial Statements of EOG and notes thereto included in this Quarterly Report on Form 10­Q.

Three Months Ended June 30, 2019 vs. Three Months Ended June 30, 2018

Operating Revenues. During the second quarter of 2019, operating revenues increased $460 million, or 11%, to $4,698 million from $4,238 million for the same period of 2018. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, for the second quarter of 2019 increased $20 million, or 1%, to $2,985 million from $2,965 million for the same period of 2018. EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $177 million for the second quarter of 2019 compared to net losses of $186 million for the same period of 2018. Gathering, processing and marketing revenues for the second quarter of 2019 increased $65 million, or 5%, to $1,501 million from $1,436 million for the same period of 2018. Net gains on asset dispositions were $8 million for the second quarter of 2019 compared to net losses of $6 million for the same period of 2018.



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Wellhead volume and price statistics for the three-month periods ended June 30, 2019 and 2018 were as follows:

                                                         Three Months Ended
                                                               June 30,
                                                          2019             2018
Crude Oil and Condensate Volumes (MBbld) (1)
United States                                            454.9             379.2
Trinidad                                                   0.6               0.8
Other International (2)                                    0.2               4.6
Total                                                    455.7             384.6

Average Crude Oil and Condensate Prices ($/Bbl) (3) United States

                                       $    61.01$ 67.91
Trinidad                                                 49.56             60.57
Other International (2)                                  55.07             70.88
Composite                                                60.99             67.93
Natural Gas Liquids Volumes (MBbld) (1)
United States                                            131.1             112.9
Other International (2)                                      -                 -
Total                                                    131.1             112.9
Average Natural Gas Liquids Prices ($/Bbl) (3)
United States                                       $    15.63$ 27.86
Other International (2)                                      -                 -
Composite                                                15.63             27.86
Natural Gas Volumes (MMcfd) (1)
United States                                            1,047               914
Trinidad                                                   273               282
Other International (2)                                     36                32
Total                                                    1,356             1,228
Average Natural Gas Prices ($/Mcf) (3)
United States                                       $     1.98$  2.56
Trinidad                                                  2.69              2.98
Other International (2)                                   4.25              4.10
Composite                                                 2.19              2.69
Crude Oil Equivalent Volumes (MBoed) (4)
United States                                            760.4             644.4
Trinidad                                                  46.1              47.8
Other International (2)                                    6.3              10.0
Total                                                    812.8             702.2

Total MMBoe (4)                                           74.0              63.9




(1) Thousand barrels per day or million cubic feet per day, as applicable.

(2) Other International includes EOG's United Kingdom, China and Canada

operations. The United Kingdom operations were sold in the fourth quarter of

2018.

(3) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the

impact of financial commodity derivative instruments (see Note 12 to the

Condensed Consolidated Financial Statements).

(4) Thousand barrels of oil equivalent per day or million barrels of oil

     equivalent, as applicable; includes crude oil and condensate, NGLs and
     natural gas. Crude oil equivalent volumes are determined using a ratio of
     1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of
     natural gas. MMBoe is calculated by multiplying the MBoed amount by the
     number of days in the period and then dividing that amount by one thousand.




                                      -24-

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Wellhead crude oil and condensate revenues for the second quarter of 2019 increased $151 million, or 6%, to $2,529 million from $2,378 million for the same period of 2018. The increase was due to an increase of 71 MBbld, or 18%, in wellhead crude oil and condensate production ($439 million), partially offset by a lower composite average price ($288 million). Increased production was primarily due to increases in the Permian Basin and the Eagle Ford. EOG's composite wellhead crude oil and condensate price for the second quarter of 2019 decreased 10% to $60.99 per barrel compared to $67.93 per barrel for the same period of 2018.

NGL revenues for the second quarter of 2019 decreased $100 million, or 35%, to $186 million from $286 million for the same period of 2018 due to a lower composite average price ($146 million), partially offset by an increase of 18 MBbld, or 16%, in production ($46 million). Increased production was primarily in the Permian Basin. EOG's composite NGL price for the second quarter of 2019 decreased 44% to $15.63 per barrel compared to $27.86 per barrel for the same period of 2018.

Wellhead natural gas revenues for the second quarter of 2019 decreased $31 million, or 10%, to $270 million from $301 million for the same period of 2018. The decrease was due to a lower average composite price ($63 million), partially offset by an increase in natural gas deliveries ($32 million). Natural gas deliveries for the second quarter of 2019 increased 128 MMcfd, or 10%, compared to the same period of 2018 due primarily to higher deliveries in the United States primarily resulting from increased production of associated natural gas from the Permian Basin and higher natural gas volumes in South Texas. EOG's composite wellhead natural gas price for the second quarter of 2019 decreased 19% to $2.19 per Mcf compared to $2.69 per Mcf for the same period of 2018.

During the second quarter of 2019, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $177 million compared to net losses of $186 million for the same period of 2018. During the second quarter of 2019, net cash received from settlements of financial commodity derivative contracts was $10 million compared to net cash paid of $66 million for the same period of 2018.

Gathering, processing and marketing revenues are revenues generated from sales of third-party crude oil, NGLs and natural gas, as well as gathering fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand. Purchases and sales of third-party crude oil and natural gas may be utilized in order to balance firm transportation capacity with production in certain areas and to utilize excess capacity at EOG-owned facilities. EOG sells sand in order to balance the timing of firm purchase agreements with completion operations and to utilize excess capacity at EOG-owned facilities. Marketing costs represent the costs to purchase third-party crude oil, natural gas and sand and the associated transportation costs, as well as costs associated with EOG-owned sand sold to third parties.

Gathering, processing and marketing revenues less marketing costs for the second quarter of 2019 decreased $15 million as compared to the same period of 2018 primarily due to lower margins on crude oil marketing activities, partially offset by higher margins on natural gas marketing activities.


Operating and Other Expenses.  For the second quarter of 2019, operating
expenses of $3,567 million were $294 million higher than the $3,273 million
incurred during the second quarter of 2018.  The following table presents the
costs per barrel of oil equivalent (Boe) for the three-month periods ended
June 30, 2019 and 2018:
                                                       Three Months Ended
                                                             June 30,
                                                         2019            2018
Lease and Well                                    $      4.70$  4.92
Transportation Costs                                     2.35             2.78
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties                                  12.55            12.83
Other Property, Plant and Equipment                      0.39             0.45
General and Administrative (G&A)                         1.65             1.63
Interest Expense, Net                                    0.67             0.99
Total (1)                                         $     22.31$ 23.60





(1)  Total excludes gathering and processing costs, exploration costs, dry hole
     costs, impairments, marketing costs and taxes other than income.




                                      -25-

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The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and net interest expense for the three months ended June 30, 2019, compared to the same period of 2018, are set forth below. See "Operating Revenues" above for a discussion of wellhead volumes.

Lease and well expenses include expenses for EOG-operated properties, as well as expenses billed to EOG from other operators where EOG is not the operator of a property. Lease and well expenses can be divided into the following categories: costs to operate and maintain crude oil and natural gas wells, the cost of workovers and lease and well administrative expenses. Operating and maintenance costs include, among other things, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power. Workovers are operations to restore or maintain production from existing wells.

Each of these categories of costs individually fluctuates from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and new areas. Operating and maintenance costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.

Lease and well expenses of $347 million for the second quarter of 2019 increased $32 million from $315 million for the same prior year period primarily due to increased operating and maintenance costs ($24 million), lease and well administrative expenses ($8 million) and workover expenditures ($4 million), all in the United States, partially offset by decreased operating and maintenance costs in the United Kingdom ($3 million) due to the sale of operations in the fourth quarter of 2018. Lease and well expenses increased in the United States primarily due to increased operating activities resulting in increased production.

Transportation costs represent costs associated with the delivery of hydrocarbon products from the lease to a downstream point of sale. Transportation costs include transportation fees, the cost of compression (the cost of compressing natural gas to meet pipeline pressure requirements), the cost of dehydration (the cost associated with removing water from natural gas to meet pipeline requirements), gathering fees and fuel costs.

Transportation costs of $174 million for the second quarter of 2019 decreased $4 million from $178 million for the same prior year period primarily due to decreased transportation costs in the Eagle Ford ($24 million), partially offset by increased transportation costs in the Permian Basin ($17 million) and Rocky Mountain area ($4 million).

DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual DD&A group calculations. There are several factors that can impact EOG's composite DD&A rate and expense, such as field production profiles, drilling or acquisition of new wells, disposition of existing wells and reserve revisions (upward or downward) primarily related to well performance, economic factors and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from period to period. DD&A of the cost of other property, plant and equipment is generally calculated using the straight-line depreciation method over the useful lives of the assets.

DD&A expenses for the second quarter of 2019 increased $108 million to $957 million from $849 million for the same prior year period. DD&A expenses associated with oil and gas properties for the second quarter of 2019 were $108 million higher than the same prior year period. The increase primarily reflects increased production in the United States.

G&A expenses of $122 million for the second quarter of 2019 increased $18 million from $104 million for the same prior year period primarily due to increased employee-related expenses resulting from expanded operations.

Interest expense, net of $50 million for the second quarter of 2019 decreased $14 million compared to the same prior year period primarily due to repayment in October 2018 of the $350 million aggregate principal amount of 6.875% Senior Notes due 2018 ($6 million), repayment in June 2019 of the $900 million aggregate principal amount of 5.625% Senior Notes due 2019 ($4 million) and higher capitalized interest ($4 million).

Exploration costs of $33 million for the second quarter of 2019 decreased $14 million from $47 million for the same prior year period primarily due to decreased geological and geophysical costs in Trinidad.



                                      -26-

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Impairments include amortization of unproved oil and gas property costs as well as impairments of proved oil and gas properties; other property, plant and equipment; and other assets. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. When circumstances indicate that a proved property may be impaired, EOG compares expected undiscounted future cash flows at a DD&A group level to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated by using the Income Approach described in the Fair Value Measurement Topic of the Financial Accounting Standards Board's Accounting Standards Codification. In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value.

Impairments of $112 million for the second quarter of 2019 were $60 million higher than impairments for the same prior year period primarily due to increased impairments of other assets in the United States. EOG recorded impairments of proved properties, other property, plant and equipment and other assets of $65 million and $10 million for the second quarter of 2019 and 2018, respectively.

Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Severance/production taxes are generally determined based on wellhead revenues, and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.

Taxes other than income for the second quarter of 2019 increased $10 million to $204 million (6.8% of wellhead revenues) compared to $194 million (6.6% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increased ad valorem/property taxes ($16 million) primarily as a result of increased valuation of the underlying assets, partially offset by decreases in severance/production taxes ($3 million), both in the United States, and an increase in credits available to EOG in the second quarter of 2019 for Texas high-cost gas severance tax rate reductions ($2 million).

Other income, net of $9 million for the second quarter of 2019 increased $17 million compared to the same prior year period primarily due to higher foreign currency exchange gains ($7 million), an increase in interest income ($6 million) and a decrease in deferred compensation expense ($5 million).

EOG recognized an income tax provision of $242 million for the second quarter of 2019 compared to an income tax provision of $196 million for the second quarter of 2018, primarily due to an increase in pretax income. The net effective tax rate of 22% for the second quarter of 2019 was unchanged from the second quarter of 2018.

Six Months Ended June 30, 2019 vs. Six Months Ended June 30, 2018

Operating Revenues. During the first six months of 2019, operating revenues increased $837 million, or 11%, to $8,756 million from $7,919 million for the same period of 2018. Total wellhead revenues for the first six months of 2019 increased $152 million, or 3%, to $5,739 million from $5,587 million for the same period of 2018. During the first six months of 2019, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $157 million compared to net losses of $246 million for the same period of 2018. Gathering, processing and marketing revenues for the first six months of 2019 increased $249 million, or 10%, to $2,787 million from $2,538 million for the same period of 2018. Net gains on asset dispositions were $4 million for the first six months of 2019 compared to net losses of $21 million for the same period of 2018.



                                      -27-

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Wellhead volume and price statistics for the six-month periods ended June 30, 2019 and 2018 were as follows:

                                                       Six Months Ended
                                                            June 30,
                                                       2019           2018
Crude Oil and Condensate Volumes (MBbld)
United States                                            445.1        369.5
Trinidad                                                   0.7          0.9
Other International                                          -          3.6
Total                                                    445.8        374.0

Average Crude Oil and Condensate Prices ($/Bbl) (1) United States

                                       $    58.63$ 66.13
Trinidad                                                 46.62        57.59
Other International                                      57.78        71.14
Composite                                                58.61        66.16
Natural Gas Liquids Volumes (MBbld)
United States                                            125.4        106.8
Other International                                          -            -
Total                                                    125.4        106.8
Average Natural Gas Liquids Prices ($/Bbl)
United States                                       $    17.84$ 26.27
Other International                                          -            -
Composite                                                17.84        26.27
Natural Gas Volumes (MMcfd)
United States                                            1,025          884
Trinidad                                                   270          288
Other International                                         37           30
Total                                                    1,332        1,202
Average Natural Gas Prices ($/Mcf) (1)
United States                                       $     2.37$  2.65
Trinidad                                                  2.80         2.93
Other International                                       4.31         4.22
Composite                                                 2.51         2.76
Crude Oil Equivalent Volumes (MBoed)
United States                                            741.3        623.6
Trinidad                                                  45.6         48.8
Other International                                        6.4          8.8
Total                                                    793.3        681.2

Total MMBoe                                              143.6        123.3





(1)  Excludes the impact of financial commodity derivative instruments (see Note
     12 to the Condensed Consolidated Financial Statements).




                                      -28-

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Wellhead crude oil and condensate revenues for the first six months of 2019 increased $250 million, or 6%, to $4,729 million from $4,479 million for the same period of 2018 due to an increase of 72 MBbld, or 19%, in wellhead crude oil and condensate production ($859 million), partially offset by a lower composite average price ($609 million). Increased production was primarily due to increases in the Permian Basin and the Eagle Ford. EOG's composite wellhead crude oil and condensate price for the first six months of 2019 decreased 11% to $58.61 per barrel compared to $66.16 per barrel for the same period of 2018.

NGL revenues for the first six months of 2019 decreased $103 million, or 20%, to $405 million from $508 million for the same period of 2018 due to a lower composite average price ($192 million), partially offset by an increase of 19 MBbld, or 17%, in NGL deliveries ($89 million). Increased production was primarily in the Permian Basin. EOG's composite NGL price for the first six months of 2019 decreased 32% to $17.84 per barrel compared to $26.27 per barrel for the same period of 2018.

Wellhead natural gas revenues for the first six months of 2019 increased $4 million, or 1%, to $605 million from $601 million for the same period of 2018. The increase was due to an increase in natural gas deliveries ($59 million), partially offset by a lower composite wellhead natural gas price ($55 million). Natural gas deliveries for the first six months of 2019 increased 130 MMcfd, or 11%, compared to the same period of 2018 due primarily to higher deliveries in the United States resulting from increased production of associated natural gas from the Permian Basin and higher natural gas volumes from South Texas, partially offset by lower production of associated natural gas in the Rocky Mountain area and lower natural gas deliveries in Trinidad. EOG's composite wellhead natural gas price for the first six months of 2019 decreased 9% to $2.51 per Mcf compared to $2.76 per Mcf for the same period of 2018.

During the first six months of 2019, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $157 million compared to net losses of $246 million for the same period of 2018. During the first six months of 2019, net cash received from settlements of financial commodity derivative contracts was $31 million compared to net cash paid for settlements of financial commodity derivative contracts of $88 million for the same period of 2018.

Gathering, processing and marketing revenues less marketing costs for the first six months of 2019 increased $5 million as compared to the same period of 2018 primarily due to higher margins on natural gas marketing activities.

Operating and Other Expenses. For the first six months of 2019, operating expenses of $6,749 million were $669 million higher than the $6,080 million incurred during the same period of 2018. The following table presents the costs per Boe for the six-month periods ended June 30, 2019 and 2018:

                                        Six Months Ended
                                             June 30,
                                         2019           2018
Lease and Well                      $     4.76$  4.99
Transportation Costs                      2.44           2.88
DD&A -
Oil and Gas Properties                   12.40          12.49
Other Property, Plant and Equipment       0.39           0.46
G&A                                       1.59           1.61
Interest Expense, Net                     0.73           1.02
Total (1)                           $    22.31$ 23.45

(1) Total excludes gathering and processing costs, exploration costs, dry hole

costs, impairments, marketing costs and taxes other than income.

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and net interest expense for the six months ended June 30, 2019, compared to the same period of 2018 are set forth below. See "Operating Revenues" above for a discussion of wellhead volumes.

Lease and well expenses of $684 million for the first six months of 2019 increased $69 million from $615 million for the same prior year period primarily due to higher operating and maintenance costs ($48 million), higher workover expenditures ($17 million) and higher lease and well administrative costs ($12 million), all in the United States, partially offset by lower operating and maintenance costs in the United Kingdom ($8 million) due to the sale of operations in the fourth quarter of 2018. Lease and well expenses increased in the United States primarily due to increased operating activities resulting in increased production.



                                      -29-

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Transportation costs of $351 million for the first six months of 2019 decreased $4 million from $355 million for the same prior year period primarily due to decreased transportation costs in the Eagle Ford ($40 million), partially offset by increased transportation costs in the Permian Basin ($38 million).

DD&A expenses for the first six months of 2019 increased $240 million to $1,837 million from $1,597 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first six months of 2019 were $241 million higher than the same prior year period. The increase primarily reflects increased production in the United States.

G&A expenses of $228 million for the first six months of 2019 increased $29 million from $199 million for the same prior year period primarily due to increased employee-related expenses resulting from expanded operations.

Interest expense, net of $105 million for the first six months of 2019 decreased $21 million compared to the same prior year period primarily due to repayment in October 2018 of the $350 million aggregate principal amount of 6.875% Senior Notes due 2018 ($12 million), higher capitalized interest ($6 million) and repayment in June 2019 of the $900 million aggregate principal amount of 5.625% Senior Notes due 2019 ($4 million).

Gathering and processing costs represent operating and maintenance expenses and administrative expenses associated with operating EOG's gathering and processing assets as well as natural gas processing fees from third parties. EOG pays third parties to process the majority of its natural gas production to extract NGLs.

Gathering and processing costs of $224 million for the first six months of 2019 increased $13 million compared to the same prior year period primarily due to increased operating costs in the Permian Basin ($28 million) and the Rocky Mountain area ($5 million), partially offset by decreased operating costs in the United Kingdom ($19 million) due to the sale of operations in the fourth quarter of 2018.

Exploration costs of $69 million for the first six months of 2019 decreased $13 million from $82 million for the same prior year period primarily due to decreased geological and geophysical costs in Trinidad.

Impairments of $184 million for the first six months of 2019 were $68 million higher than impairments for the same prior year period primarily due to increased impairments of other assets in the United States. EOG recorded impairments of proved properties, other property, plant and equipment and other assets of $91 million and $32 million for the first six months of 2019 and 2018, respectively.

Taxes other than income for the first six months of 2019 increased $24 million to $397 million (6.9% of wellhead revenues) from $373 million (6.7% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increased ad valorem/property taxes in the United States ($37 million) primarily as a result of increased valuation of the underlying assets, partially offset by decreases in severance/production taxes in the United States ($6 million) and Trinidad ($3 million), and an increase in credits available to EOG in the second quarter of 2019 for Texas high-cost severance tax rate reductions ($4 million).

Other income, net of $14 million for the first six months of 2019 increased $22 million compared to the same prior year period primarily due to an increase in interest income ($11 million) and higher foreign currency exchange gains ($8 million).

EOG recognized an income tax provision of $433 million for the first six months of 2019 compared to an income tax provision of $371 million for the same period in 2018, primarily due to an increase in pretax income. The net effective tax rate for the first six months of 2019 increased to 23% from 22% for the first six months of 2018.


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Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the six months ended June 30, 2019, were funds generated from operations. The primary uses of cash were funds used in operations; exploration and development expenditures; long-term debt repayments; dividend payments to stockholders; and other property, plant and equipment expenditures. During the first six months of 2019, EOG's cash balance decreased $396 million to $1,160 million from $1,556 million at December 31, 2018.

Net cash provided by operating activities of $4,294 million for the first six months of 2019 increased $801 million compared to the same period of 2018 primarily due to a decrease in net cash paid for income taxes ($395 million), a favorable change in working capital ($252 million), an increase in wellhead revenues ($152 million) and an increase in cash received for settlements of commodity derivative contracts ($120 million), partially offset by an increase in cash operating expenses ($104 million).

Net cash used in investing activities of $3,524 million for the first six months of 2019 increased by $434 million compared to the same period of 2018 due to an increase in additions to oil and gas properties ($466 million) and an unfavorable change in components of working capital associated with investing activities ($5 million), partially offset by a decrease in additions to other property, plant and equipment ($28 million) and an increase in proceeds from the sale of assets ($9 million).

Net cash used in financing activities of $1,166 million for the first six months of 2019 included repayments of long-term debt ($900 million) and cash dividend payments ($255 million). Net cash used in financing activities of $228 million for the first six months of 2018 included cash dividend payments ($204 million) and purchases of treasury stock in connection with stock compensation plans ($32 million).

Total Expenditures. For the year 2019, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $6.1 billion to $6.5 billion, excluding acquisitions and non-cash transactions. The table below sets out components of total expenditures for the six-month periods ended June 30, 2019 and 2018 (in millions):

                                                   Six Months Ended
                                                        June 30,
                                                    2019           2018
Expenditure Category
Capital
Exploration and Development Drilling           $    2,692$ 2,503
Facilities                                            338            340
Leasehold Acquisitions (1)                            145            172
Property Acquisitions (2)                             322             37
Capitalized Interest                                   18             11
Subtotal                                            3,515          3,063
Exploration Costs                                      69             82
Dry Hole Costs                                          4              5
Exploration and Development Expenditures            3,588          3,150
Asset Retirement Costs                                 60             31

Total Exploration and Development Expenditures 3,648 3,181 Other Property, Plant and Equipment (3)

               117            193
Total Expenditures                             $    3,765$ 3,374





(1)  Leasehold acquisitions included $54 million and $60 million for the
     six-month periods ended June 30, 2019 and 2018, respectively, related to
     non-cash property exchanges.


(2)  Property acquisitions included $18 million and $23 million for the six-month
     periods ended June 30, 2019 and 2018, respectively, related to non-cash
     property exchanges.


(3)  Other property, plant and equipment included $48 million of non-cash
     additions for the six-month period ended June 30, 2018 made in connection
     with a finance lease transaction in the Permian Basin.




                                      -31-

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Exploration and development expenditures of $3,588 million for the first six months of 2019 were $438 million higher than the same period of 2018 primarily due to increased property acquisitions ($285 million) and increased exploration and drilling expenditures in the United States ($181 million), partially offset by decreased leasehold acquisitions ($27 million). Exploration and development expenditures for the first six months of 2019 of $3,588 million consisted of $3,010 million in development drilling and facilities, $322 million in property acquisitions, $238 million in exploration and $18 million in capitalized interest. Exploration and development expenditures for the first six months of 2018 of $3,150 million consisted of $2,839 million in development drilling and facilities, $263 million in exploration, $37 million in property acquisitions and $11 million in capitalized interest.

The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other economic factors. EOG has significant flexibility with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to its operations, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG.

Commodity Derivative Transactions. As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's Annual Report on Form 10-K for the year ended December 31, 2018, filed on February 26, 2019, EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for crude oil and natural gas. EOG utilizes financial commodity derivative instruments, primarily price swap, option, swaption, collar and basis swap contracts, as a means to manage this price risk. EOG has not designated any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for financial commodity derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Condensed Consolidated Statements of Income and Comprehensive Income. The related cash flow impact is reflected in Cash Flows from Operating Activities on the Condensed Consolidated Statements of Cash Flows.

The total fair value of EOG's commodity derivative contracts was reflected on the Condensed Consolidated Balance Sheets at June 30, 2019, as a net asset of $135 million.

Prices received by EOG for its crude oil production generally vary from NYMEX West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts through July 29, 2019. The weighted average price differential expressed in dollars per barrel ($/Bbl) represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in barrels per day (Bbld) covered by the basis swap contracts.

                           Midland Differential Basis Swap Contracts
                                                                            Weighted Average
                                                                Volume     Price Differential
                                                                (Bbld)           ($/Bbl)
  2019
  January 1, 2019 through August 31, 2019 (closed)              20,000     $           1.075
  September 1, 2019 through December 31, 2019                   20,000                 1.075


EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts through July 29, 2019. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.

                          Gulf Coast Differential Basis Swap Contracts
                                                                            Weighted Average
                                                                Volume     Price Differential
                                                                (Bbld)           ($/Bbl)
  2019
  January 1, 2019 through August 31, 2019 (closed)              13,000     $           5.572
  September 1, 2019 through December 31, 2019                   13,000                 5.572



                                      -32-

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Presented below is a comprehensive summary of EOG's crude oil price swap
contracts through July 29, 2019, with notional volumes expressed in Bbld and
prices expressed in $/Bbl.
                                 Crude Oil Price Swap Contracts
                                                                               Weighted Average
                                                             Volume (Bbld)      Price ($/Bbl)
2019
April 2019 (closed)                                                25,000     $          60.00
May 1, 2019 through June 30, 2019 (closed)                        150,000                62.50
July 1, 2019 through December 31, 2019                            150,000                62.50



Presented below is a comprehensive summary of EOG's natural gas price swap
contracts through July 29, 2019, with notional volumes expressed in million
British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars
per MMBtu ($/MMBtu).
                          Natural Gas Price Swap Contracts
                                                                        Weighted
                                                                     Average Price
                                                 Volume (MMBtud)       ($/MMBtu)
2019
April 1, 2019 through August 31, 2019 (closed)           250,000    $          2.90
September 1, 2019 through October 31, 2019               250,000               2.90





                                      -33-

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Information Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, capital expenditures, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness or pay and/or increase dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:

•         the timing, extent and duration of changes in prices for, supplies of,
          and demand for, crude oil and condensate, natural gas liquids, natural
          gas and related commodities;


•         the extent to which EOG is successful in its efforts to acquire or
          discover additional reserves;


•         the extent to which EOG is successful in its efforts to economically
          develop its acreage in, produce reserves and achieve anticipated
          production levels from, and maximize reserve recovery from, its
          existing and future crude oil and natural gas exploration and
          development projects;


•         the extent to which EOG is successful in its efforts to market its
          crude oil and condensate, natural gas liquids, natural gas and related
          commodity production;


•         the availability, proximity and capacity of, and costs associated with,
          appropriate gathering, processing, compression, storage, transportation
          and refining facilities;


•         the availability, cost, terms and timing of issuance or execution of,
          and competition for, mineral licenses and leases and governmental and
          other permits and rights-of-way, and EOG's ability to retain mineral
          licenses and leases;


•         the impact of, and changes in, government policies, laws and
          regulations, including tax laws and regulations; climate change and
          other environmental, health and safety laws and regulations relating to
          air emissions, disposal of produced water, drilling fluids and other
          wastes, hydraulic fracturing and access to and use of water; laws and
          regulations imposing conditions or restrictions on drilling and
          completion operations and on the transportation of crude oil and
          natural gas; laws and regulations with respect to derivatives and
          hedging activities; and laws and regulations with respect to the import
          and export of crude oil, natural gas and related commodities;


•         EOG's ability to effectively integrate acquired crude oil and natural
          gas properties into its operations, fully identify existing and
          potential problems with respect to such properties and accurately
          estimate reserves, production and costs with respect to such
          properties;


•         the extent to which EOG's third-party-operated crude oil and natural
          gas properties are operated successfully and economically;


•         competition in the oil and gas exploration and production industry for
          the acquisition of licenses, leases and properties, employees and other
          personnel, facilities, equipment, materials and services;


•         the availability and cost of employees and other personnel, facilities,
          equipment, materials (such as water and tubulars) and services;


•         the accuracy of reserve estimates, which by their nature involve the
          exercise of professional judgment and may therefore be imprecise;


•         weather, including its impact on crude oil and natural gas demand, and
          weather-related delays in drilling and in the installation and
          operation (by EOG or third parties) of production, gathering,
          processing, refining, compression, storage and transportation
          facilities;


•         the ability of EOG's customers and other contractual counterparties to
          satisfy their obligations to EOG and, related thereto, to access the
          credit and capital markets to obtain financing needed to satisfy their
          obligations to EOG;


•         EOG's ability to access the commercial paper market and other credit
          and capital markets to obtain financing on terms it deems acceptable,
          if at all, and to otherwise satisfy its capital expenditure
          requirements;


•         the extent to which EOG is successful in its completion of planned
          asset dispositions;

• the extent and effect of any hedging activities engaged in by EOG;




                                      -34-

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•         the timing and extent of changes in foreign currency exchange rates,
          interest rates, inflation rates, global and domestic financial market
          conditions and global and domestic general economic conditions;


•         geopolitical factors and political conditions and developments around
          the world (such as the imposition of tariffs or trade or other economic
          sanctions, political instability and armed conflict), including in the
          areas in which EOG operates;


•         the use of competing energy sources and the development of alternative
          energy sources;


•         the extent to which EOG incurs uninsured losses and liabilities or
          losses and liabilities in excess of its insurance coverage;

• acts of war and terrorism and responses to these acts;

• physical, electronic and cybersecurity breaches; and


•         the other factors described under ITEM 1A, Risk Factors, on pages 13
          through 22 of EOG's Annual Report on Form 10-K for the fiscal year
          ended December 31, 2018, and any updates to those factors set forth in
          EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on
          Form 8-K.


In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.




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                         PART I.  FINANCIAL INFORMATION

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